Process for treating a hydrocarbon stream and an apparatus relating thereto

ABSTRACT

One exemplary embodiment can be a process for treating a hydrocarbon stream. The stream can include passing the hydrocarbon stream into a vessel containing a packed zone and a coalescing zone, passing an amine stream into the vessel at a location above an inlet for the hydrocarbon stream, and withdrawing the hydrocarbon stream.

CROSS-REFERENCE TO RELATED APPLICATION

This application is a Division of copending application Ser. No.13/920,432 filed Jun. 18, 2013, the contents of which are herebyincorporated by reference in its entirety.

FIELD OF THE INVENTION

This invention generally relates to a process for treating a hydrocarbonstream, and an apparatus relating thereto.

DESCRIPTION OF THE RELATED ART

Amine carryover and amine solubility in hydrocarbons, such as fuel gasand liquefied petroleum gas, can cause amine loss and major upsets incaustic extraction and downstream units. When mixed with causticsolutions, amines may cause emulsions in hydrocarbons resulting inoff-specification product, high caustic consumption, corrosion of carbonsteel in a vapor phase of a separator, and loss of production due tooperating at lower hydrocarbon flow rates. It would be desirable toeliminate these problems by making the hydrocarbon streams entering theextraction unit amine free. Often, the amine carryover is accentuatedwhen processing a liquefied petroleum gas derived from fluid catalyticcracking and coker units. Knockout drums can remove entrained amine, andamine water washes may remove soluble amine; however, such devices aretypically insufficient to provide the requisite separation. Hence, thereis a desire to provide a suitable amine process that can reduce costs byreducing vessel size and possibly eliminate equipment.

SUMMARY OF THE INVENTION

One exemplary embodiment can be a process for treating a hydrocarbonstream. The stream can include passing the hydrocarbon stream into avessel containing a packed zone and a coalescing zone, passing an aminestream into the vessel at a location above an inlet for the hydrocarbonstream, and withdrawing the hydrocarbon stream.

Another exemplary embodiment may be a process for treating a hydrocarbonstream. The process may include passing the hydrocarbon stream havinghydrogen sulfide to an absorption zone, passing an amine stream to anabsorption zone for absorbing hydrogen sulfide, and passing thehydrocarbon stream from the absorption zone to a coalescing zone forremoving one or more amines.

A further embodiment can be an apparatus for removing hydrogen sulfidefrom a hydrocarbon stream. The apparatus may include an amine absorptionzone having a first vessel containing a packed zone and a coalescingzone, a prewash zone including a second vessel downstream of the amineabsorption zone, an extraction zone downstream from the prewash zone,and an alkali regeneration zone in communication with the extractionzone. Often, the coalescing zone has a hydrophilic mesh.

The embodiments disclosed herein can use a coalescing media to enhancethe separation of amine and hydrocarbons at the top of an absorbercolumn and/or in a knockout drum. Generally, this coalescing mediaenhances the separation of spent water and hydrocarbons in the aminewater washes. Typically, the coalescing media has hydrophilic propertiesincluding a coated or an uncoated mesh, a corrugated sheet media, orother liquid-liquid coalescing media.

One exemplary coalescing media may include a fluoropolymer-coated meshfor separating hydrocarbons from an aqueous solution, although astainless steel mesh may alternatively be utilized. Preferably, smallervessels and/or elimination of some vessels may reduce the overall costand facilitate construction of modular units. Thus, the embodimentsdisclosed herein may reduce both capital and operating costs of thetreating units.

DEFINITIONS

As used herein, the term “stream” can include various hydrocarbonmolecules, such as straight-chain, branched, or cyclic alkanes, alkenes,alkadienes, and alkynes, and optionally other substances, such as gases,e.g., hydrogen, or impurities, such as heavy metals, and sulfur andnitrogen compounds. The stream can also include aromatic andnon-aromatic hydrocarbons. Moreover, the hydrocarbon molecules may beabbreviated C₁, C₂, C₃ . . . C_(n) where “n” represents the number ofcarbon atoms in the one or more hydrocarbon molecules. Furthermore, asuperscript “+” or “−” may be used with an abbreviated one or morehydrocarbons notation, e.g., C₃ ⁺ or C₃−, which is inclusive of theabbreviated one or more hydrocarbons. As an example, the abbreviation“C₃ ⁺” means one or more hydrocarbon molecules of three carbon atomsand/or more. In addition, the term “stream” may be applicable to otherfluids, such as aqueous and non-aqueous solutions of alkaline or basiccompounds, such as sodium hydroxide.

As used herein, the term “zone” can refer to an area including one ormore equipment items and/or one or more sub-zones. Equipment items caninclude one or more reactors or reactor vessels, heaters, exchangers,pipes, pumps, compressors, and controllers. Additionally, an equipmentitem, such as a reactor, dryer, or vessel, can further include one ormore zones or sub-zones.

As used herein, the term “rich” can mean an amount of at least generallyabout 50%, and preferably about 70%, by mole, of a compound or class ofcompounds in a stream. If referring to a solute in solution, e.g., oneor more disulfide compounds in an alkaline solution, the term “rich” maybe referenced to the equilibrium concentration of the solute. As anexample, about 5%, by mole, of a solute in a solvent may be consideredrich if the concentration of solute at equilibrium is about 10%, bymole.

As used herein, the term “substantially” can mean an amount of at leastgenerally about 80%, preferably about 90%, and optimally about 99%, bymole, of a compound or class of compounds in a stream.

As used herein, the terms “absorbent” and “absorber” include,respectively, an adsorbent and an adsorber, and relates, but is notlimited to, absorption, and/or adsorption.

As used herein, the term “coupled” can mean two items, directly orindirectly, joined, fastened, associated, connected, or formedintegrally together either by chemical or mechanical means, by processesincluding stamping, molding, or welding. What is more, two items can becoupled by the use of a third component such as a mechanical fastener,e.g., a screw, a nail, a bolt, a staple, or a rivet; an adhesive; or asolder.

As used herein, the term “coalescer” may be a media containing anoptionally coated metal mesh, glass fibers, or other material tofacilitate separation of immiscible liquids of similar density.

As used herein, the term “immiscible” can mean two or more phases thatcannot be uniformly mixed or blended.

As used herein, the term “phase” may mean a liquid, a gas, or asuspension including a liquid and/or a gas, such as a foam, aerosol, orfog. A phase may include solid particles. Generally, a fluid can includeone or more gas, liquid, and/or suspension phases.

As used herein, the term “alkali” can mean any substance that insolution, typically a water solution, has a pH value greater than about7.0, and exemplary alkali can include sodium hydroxide, potassiumhydroxide, or ammonia. Such an alkali in solution may be referred to as“an alkaline solution” or “an alkaline” and includes caustic, i.e.,sodium hydroxide in water.

As used herein, the term “parts per million” may be abbreviated hereinas “ppm” and “weight ppm” may be abbreviated herein as “wppm”.

As used herein, the term “mercaptan” typically means thiol and may beused interchangeably therewith, and can include compounds of the formulaRSH as well as salts thereof, such as mercaptides of the formula RS-M⁺where R is a hydrocarbon group, such as an alkyl or aryl group, that issaturated or unsaturated and optionally substituted, and M is a metal,such as sodium or potassium.

As used herein, the term “disulfides” can include dimethyldisulfide,diethyldisulfide, and ethylmethyldisulfide, and possibly other specieshaving the molecular formula RSSR′ where R and R′ are each,independently, a hydrocarbon group, such as an alkyl or aryl group, thatis saturated or unsaturated and optionally substituted. Typically, adisulfide is generated from the oxidation of a mercaptan-containingcaustic and forms a separate hydrocarbon phase that is not soluble inthe aqueous caustic phase. Generally, the term “disulfides” as usedherein excludes carbon disulfide (CS₂).

As used herein, the weight percent or ppm of sulfur, e.g., “wppm-sulfur”is the amount of sulfur, and not the amount of the sulfur-containingspecies unless otherwise indicated. As an example, methylmercaptan,CH₃SH, has a molecular weight of 48.1 with 32.06 represented by thesulfur atom, so the molecule is about 66.6%, by weight, sulfur. As aresult, the actual sulfur compound concentration can be higher than thewppm-sulfur from the compound. An exception is that the disulfidecontent in caustic can be reported as the wppm of the disulfidecompound.

As used herein, the term “lean” can describe a fluid optionally havingbeen treated and desired levels of sulfur, including one or moremercaptans and one or more disulfides for treating one or more C₁-C₄hydrocarbons.

As used herein, the term “regeneration” with respect to a solvent streamcan mean removing one or more disulfide sulfur species from the solventstream to allow its reuse.

As used herein, the terms “degrees Celsius” may be abbreviated “° C.”and the term “kilopascal” may be abbreviated “KPa” and all pressuresdisclosed herein are absolute.

As depicted, process flow lines in the figures can be referred to,interchangeably, as, e.g., lines, pipes, branches, distributors,streams, effluents, feeds, products, portions, catalysts, withdrawals,recycles, suctions, discharges, and caustics.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic depiction of an exemplary apparatus.

FIG. 2 is an elevational, cross-sectional view of an exemplaryabsorption zone.

FIG. 3 is an elevational, cross-sectional view of an exemplarycoalescing zone.

FIG. 4 is an elevational, cross-sectional view of another exemplarycoalescing zone.

FIG. 5 is an elevational, cross-sectional view of a further exemplarycoalescing zone.

DETAILED DESCRIPTION

Referring to FIG. 1, an apparatus 10 for removing hydrogen sulfide froma hydrocarbon stream can include an amine absorption zone or absorptionzone 100, a coalescing zone 200, a prewash zone 400, an extraction zone500, and an alkali regeneration zone 600. A hydrocarbon stream 40including one or more C₄— hydrocarbons, such as a liquefied petroleumgas or a fuel gas containing one or more thiol compounds, may beprovided to the amine absorption zone 100. Generally, the hydrocarbonstream 40 may be rich in or substantially has one or more C₄—hydrocarbons. The hydrocarbon stream 40 may be one or more liquids,gases, or a mixture of one or more gases and liquids.

The amine absorption zone 100 can receive an amine stream 60 forabsorbing hydrogen sulfide. The amine is described in further detailbelow. In one exemplary embodiment, the amine absorption zone 100 caninclude an amine absorber or a first vessel containing a series oftrays. The hydrocarbon stream 40 can be provided via a distributor belowa mid-point of the vessel. A nozzle for delivering the amines can bedisposed toward the top of the vessel to allow counter-current contactof the amines descending in the vessel and the hydrocarbon ascending inthe vessel. Generally, the amines in the vessel react with hydrogensulfide to yield thiol amides.

The conditions within the amine absorption zone 100 can include atemperature of about 0° to about 100° C., and pressure of about 100 toabout 4,000 KPa. Generally, there are about 10 to about 25 moles ofamine for each mole of combined hydrogen sulfide and carbon dioxide tobe removed. Typically, the hydrocarbon stream 40 contains approximatelyabout 1,000 to about 2,000 wppm of hydrogen sulfide that is reduced downto about 15 wppm of hydrogen sulfide concentration in the withdrawnhydrocarbon stream. An amine effluent stream rich in thiol amides canexit the bottom of the amine absorber vessel while a hydrocarbon stream80 may exit the top of the amine absorber vessel with a substantiallyreduced concentration of hydrogen sulfide. Additionally, carbon dioxideor other acid gases that are possibly present in the hydrocarbon stream40 may also react with the amines and are absorbed into the amineeffluent stream leaving the amine absorber vessel.

A rich amine stream 70 can exit the amine absorption zone 100, which maybe regenerated. An exemplary amine absorption zone is disclosed in,e.g., U.S. Pat. No. 7,381,309. Another version of an amine absorptionzone 100 is discussed hereinafter.

The hydrocarbon stream 80 from the amine absorption zone 100 can be sentto the optional coalescing zone 200, as hereinafter described. Ahydrocarbon stream 90 can be obtained and sent to the prewash zone 400containing a prewash, or a second vessel 410 for removing hydrogensulfide by converting to, e.g., sodium sulfide. Subsequently, a prewasheffluent 420 can be sent to an extraction zone 500 downstream from theprewash zone 400. A lean alkali stream 610 at least partially obtainedfrom the alkali regeneration zone 600 may be split into a portion 620combined with the hydrocarbon stream 90 prior to entering the prewashzone 400 and another portion 630 provided to the extraction zone 500.Generally, a product stream 510 is obtained from the extraction zone 500and a rich alkali stream 520 can be sent to the alkali regeneration zone600, which may include an oxidation vessel and disulfide separator. Therich alkali stream 520 may be regenerated to provide a lean alkalistream 610 provided to the hydrocarbon stream 90 and extraction zone500, as discussed above. Exemplary prewash, extraction, and alkaliregeneration zones 400, 500, and 600 are disclosed in, e.g., U.S. Pat.No. 7,381,309.

Referring to FIG. 2, an exemplary amine absorption zone or absorptionzone 100 is depicted having a vessel or first vessel 120, which cancontain a packed zone 128 and a coalescing zone 136. The packed zone 128may include one or more rings or one or more trays made from ceramic ormetal; such as Raschig rings, pall rings, and sieve trays. The packedzone 128 can receive the hydrocarbon stream 40 at an inlet 42 below aninlet 62 for an amine stream 60 provided above the packed zone 128.Usually, the amine stream 60 includes at least one alkanolamine,including at least one of monoethanolamine, diethanolamine, and methyldiethanolamine, preferably monoethanolamine and diethanolamine in awater solution. Often, the amine stream 60 can include about 15 to about40%, preferably about 10 to about 20%, by weight, amine with the balancewater.

The vessel 120 can contain a hydrocarbon phase 44 and an amine phase 48forming an interface 46. The amine phase 48 can be withdrawn as the richamine stream 70 and regenerated. The hydrocarbon phase 44 can rise pastthe packed zone 128 to the coalescing zone 136, which can include ahydrophilic media. Generally, the hydrophilic media includes at leastone of a metal mesh that is optionally coated; one or more glass fibers;or a metal, such as stainless steel, mesh. Desirably, the coating may bean oleophobic and/or hydrophilic coating usually suited for an oilphase. One exemplary mesh may have a coating sold under the tradedesignation COALEX or KOCH-OTTO YORK™ separations technology byKoch-Glitsch, LP of Wichita, Kans. Alternatively, the coalescing zone136 can include one or more vanes, such as metal and optionally coatedwith a hydrophilic coating. As such, the coalescing zone 136 canminimize the formation of emulsions, thereby potentially loweringutility and chemical costs, such as amine, alkali, and process water,and lowering operating costs.

Alternatively, if the hydrocarbons are in a gas phase, such as a fuelgas, the coalescing zone 136 may be replaced with a demister. Such ademister may be a vane or mesh, and constructed from any suitablematerial such as a metal, e.g., stainless steel. The hydrocarbon phase44 can rise through the coalescing zone 136 and exit the vessel 120 asthe hydrocarbon stream 80, which can pass to the coalescing zone 200 ordirectly to the prewash zone 400.

Referring to FIG. 3, the coalescing zone 200 for removing one or moreamines is depicted. The coalescing zone 200 may include a vessel 210,which in this depicted embodiment is orientated horizontally, but inother embodiments may be orientated vertically. Often the vessel 210includes a body 224 formed integrally with a boot 230. Typically, thevessel 210 contains a coalescing media 220 that occupies a vertical,cross-sectional slice of the body 224 of the vessel 210, therebydividing the body 224 into two chambers. The hydrocarbon stream 80 canenter the vessel 210 and pass through the coalescing media 220 to formtwo phases, namely a hydrocarbon phase 240 and an amine phase 250forming an interface 248 typically in the boot 230. The coalescing media220 can include at least one of a mesh, optionally coated, and one ormore vanes. Desirably, the coalescing media is hydrophilic and can beone of the specific examples as described above. The amine phase 250 canbe withdrawn as a rich amine stream 254 and be sent to any suitabledestination, including an amine regeneration unit. A control valve canregulate the amount of the rich amine stream 254 for maintaining adesired level in the boot 230 by communicating with a level controller.The hydrocarbon phase 240 can be withdrawn as the hydrocarbon stream 90and provided to the downstream extraction zone 500.

Referring to FIG. 4, another version of the coalescing zone 200 isdepicted. In this exemplary version, the coalescing zone 200 can includea substantially horizontal vessel 270 that may receive the hydrocarbonstream 80 that is combined with a stream 274 including substantiallywater and a discharge stream 306, as hereinafter described, to form acombined stream 278 that may enter the vessel 270. The vessel 270 cancontain a coalescing media 280 that can occupy a substantially verticalslice of the vessel 270 and divide the vessel 270 into two chambers. Thecoalescing media 280 can separate the combined stream into a hydrocarbonphase 284 forming an interface 292 with an aqueous phase 294. Theaqueous phase 294 can be withdrawn as a water stream 298 and split intoa recycle stream 302 and a purge stream 308, which can be sent to anysuitable destination, including an amine regeneration unit. A controlvalve can regulate the amount withdrawn as the water stream 298 andcommunicate with a level controller to maintain the level in the vessel270. The recycle stream 302 can be provided to a suction of a pump 304and the discharge stream 306 combined with the streams 80 and 274. Thehydrocarbon stream 90 can be withdrawn from the hydrocarbon phase 284 inthe vessel 270 and provided to the downstream extraction zone 500.

Referring to FIG. 5, a further version of the coalescing zone 200 isdepicted. In this exemplary version, the coalescing zone 200 can includea substantially vertical vessel 330 that may receive the hydrocarbonstream 80 that is combined with a stream 334 including substantiallywater and a discharge stream 366, as hereinafter described, to form acombined stream 338 that may enter the vessel 330. The vessel 330 cancontain a coalescing media 340 that can occupy a substantiallyhorizontal slice of the vessel 330 and divide the vessel 330 into twochambers. The coalescing media 340 can separate water from thehydrocarbons. The vessel 330 can also contain a hydrocarbon phase 344forming an interface 350 with an aqueous phase 354. The aqueous phase354 can be withdrawn as a water stream 358 and split into a recyclestream 362 and a purge stream 368, which can be sent to any suitabledestination, including an amine regeneration unit. A control valve canregulate the amount withdrawn as the water stream 358 and communicatewith a level controller to maintain the level in the vessel 330. Therecycle stream 362 can be provided to a suction of a pump 364 and thedischarge steam 366 combined with the streams 80 and 334. Thehydrocarbon stream 90 can be withdrawn from the hydrocarbon phase 344 inthe vessel 330 and provided to the downstream extraction zone 500.

Without further elaboration, it is believed that one skilled in the artcan, using the preceding description, utilize the present invention toits fullest extent. The preceding preferred specific embodiments are,therefore, to be construed as merely illustrative, and not limitative ofthe remainder of the disclosure in any way whatsoever.

In the foregoing, all temperatures are set forth in degrees Celsius and,all parts and percentages are by weight, unless otherwise indicated.

From the foregoing description, one skilled in the art can easilyascertain the essential characteristics of this invention and, withoutdeparting from the spirit and scope thereof, can make various changesand modifications of the invention to adapt it to various usages andconditions.

1. An apparatus for removing hydrogen sulfide from a hydrocarbon stream,comprising: A) an amine absorption zone comprising a first vesselcontaining a packed zone and a coalescing zone wherein the coalescingzone comprises a hydrophilic mesh; B) a prewash zone comprising a secondvessel downstream of the amine absorption zone; C) an extraction zonedownstream from the prewash zone; and D) an alkali regeneration zone incommunication with the extraction zone.